Tuesday, May 31, 2011

Today's Wall St. Journal (subscription required) includes an op-ed calling for a stricter US boycott of Iran than the current one that prohibits importing Iranian oil. The proposal from Reuel Marc Gerecht and Mark Dubowitz of the Foundation for the Defense of Democracies would go a step farther, barring the importation of petroleum products that contain any components processed from Iranian crude elsewhere. Before any fuels or petrochemical products could be brought to the US, exporters "would have to certify that no Iranian oil was involved in its manufacture." Yet while the authors have clearly thought about how to maximize the impact of such a rule on the government of Iran, I'm not sure they've examined the potential impact on the US carefully enough. If their arguments about how European refiners would react to such a boycott are correct, then U.S. gasoline prices would likely rise as a result of these restrictions.

The logic of the proposal is grounded in fact. The US imports significant quantities of gasoline from Europe, though lately most of it is in the form of gasoline blending components, rather than finished gasoline that is ready to be put into a pipeline or sold over a refinery's or blending facility's truck rack. Last year total US gasoline imports averaged almost 900,000 barrels per day, with 39% coming from EU countries led by the UK, Netherlands, Spain and France. It's also true that many European refineries process some Iranian crude. In 2010, the EU imported 471,000 bbl/day of crude oil from Iran, comprising just over 4% of total EU oil imports of 11.1 million barrels per day. (Compare that to US oil imports in 2010 of 9.2 million bbl/day.) This amounts to roughly a fifth of total Iranian crude oil exports. At least on the surface, it looks like it shouldn't be too hard for European refiners to forgo this small input, in order to be able to continue exporting gasoline and other oil-derived products to the USA.

In practice, I think it would be more difficult for European refiners to make that adjustment than the authors imagine. For starters, those refineries capable of exporting gasoline to the US must generally be located near ports, rather than inland, and likely run more Iranian crude than the EU average, since this oil is delivered by large tankers. Then there's the question of how much Iranian crude a refinery could run and still be able to certify its products to be Iran-free. If the standard were simply that you couldn't export a larger proportion of your products than the proportion of non-Iranian oil in your crude slate, that probably wouldn't change what any refiner is currently doing, since most of their output goes into the local market. Certifying that there were no molecules of Iranian origin in any products destined for the US would essentially require running no Iranian crude at all, because of the way that most refineries operate and manage their inventories of crude oil and unfinished products.

I presume that's what the authors have in mind, because it would certainly exert the greatest market pressure on the price of Iranian crude. However, substituting one crude oil for another in a refinery isn't like substituting one brand of cola for another in a fast-food restaurant. We've seen a prime example of that recently with the disproportionately large disruption caused by the curtailment of exports of high-quality oil from Libya. Refineries tend to be optimized around certain proportions of well-known crudes, with shifts in those proportions mainly driven by changes in the value of the products they yield, within a range set by the capabilities of the specific hardware. In other words, if your refinery model is telling you to run x% of Iranian Light, then choosing something else in order to be able to sell into the US market comes at a cost.

That cost would be passed on to companies importing European gasoline into the US in two ways. First, it would require a higher price to make it worthwhile for the exporting refinery to produce a cargo to US specifications. Less directly but just as significantly, it would reduce the number of refineries competing for the export opportunity, because some would simply find the changes too onerous, unless the premium they collected was really large. That would create a smaller pool of suppliers with higher costs. That's not what you want to face as a buyer.

Market dynamics might also amplify this effect. A portion of the gasoline exported from Europe to the US flows not under long-term contracts, but as "spot" cargoes shipped in response to occasional wide price differences between there and here. That's exactly the kind of trading I was involved in when I worked in London in the early '90s. Such "arbitrage opportunities" often result from supply problems such as refinery accidents and other unanticipated shutdowns, large weather events, or other situations leading to a local or regional price spike. As a result, much of the impact on the US from the authors' proposal could be delivered when gas prices here would already be rising, thus adding to the economic impact of a price spike.

Perhaps paying more at the pump to drive down the value of Iranian crude in the global market is a price most Americans would be willing to accept. I'd gladly kick in a few cents per gallon for that purpose, since I remain extremely skeptical of Iranian assurances that their nuclear program is entirely for peaceful purposes. Nothing has materially changed my view of that since my detailed analysis in 2005. However, I suspect that the strong likelihood that such a boycott would entail a certain amount of "blowback" at home would complicate the politics of passing the necessary legislation, particularly when gas prices are already quite high by US standards.

Wednesday, May 25, 2011

It's rare to run across a novel form of renewable energy that hasn't already been touted as the Next Big Thing and the potential savior of humanity. Work on harnessing salinity gradient power, one aspect of which is also known as "osmotic power", has proceeded in relative obscurity, with only one demonstration-scale installation that I'm aware of, in Norway. However, recent developments at Stanford University, as reported in Technology Review, hold the promise of extracting electricity directly from the difference in salt concentration between fresh water and seawater. If it can be scaled up as indicated, it could offer yet another renewable energy option for coastal communities, though as with most others, it is unlikely to be free of undesired consequences. So far as I know, the law of no free lunches has not yet been repealed.

Most forms of energy production, renewable or otherwise, depend on taking advantage of some kind of gradient--differences in temperature, pressure, or another characteristic between two locations. In some cases, these gradients are inherent in the primary energy source involved, such as the pressure gradients that produce the wind harnessed by wind turbines, or the temperature gradients that drive geothermal power plants. In other cases, the gradient is created by the process of energy conversion in some device, such as an internal combustion engine, gas turbine or nuclear reactor. For most of us, it's probably easier to relate to the pressure and temperature gradients that drive such machines than to visualize the concentration gradients that Dr. Cui's team at Stanford was investigating. Reading about their work dusted off the cobwebs from my chemical engineering mass transfer studies, long ago.

The "mixing entropy battery" the researchers created uses electrodes chosen for their affinity for sodium and chloride ions, with surfaces optimized through the application of nanotechnology. By charging it from an external power source while immersed in fresh water and then discharging it while filled with salt water, they are able to extract more energy than they put into it. This is not perpetual motion, because the extra energy comes from exploiting the concentration difference between the two fluids. Impressively, they extracted 74% of that energy potential in their tests; few energy cycles recover more than 50% of the energy of their sources. The catch is that like any battery, the process stops when the electrodes are saturated. At that point, the battery must be recharged in freshwater. This cycle can be repeated many times.

Although this technique might be used to produce smaller-scale rechargeable batteries for consumer devices or perhaps even cars, the researchers apparently had in mind larger-scale applications that would exploit the differences in salinity where a river meets the sea. Not only are such locations quite common, but they also tend to be near centers of population, because of the historical relationship between waterborne commerce and settlements. They have apparently calculated that the global potential of the concentration gradients in estuaries could meet 13% of the world's energy needs, or around 2 terawatts (2 million Megawatts.)

What's not clear from what I've read of their work is how much of the salinity gradient in an estuary could be tapped without significantly affecting the local ecosystem. Even though the amount of salt returned to the estuary would match what was taken out, performing the relevant mixing somewhere else--inside a power plant--would alter the preexisting conditions. That might not be catastrophic, particularly if the scale of the plant were limited to the natural variation in water flow caused by seasonal rainfall patterns, but it would still count as an environmental impact. I don't regard that as a reason not to pursue this technology, because everything we do at the scale of our global civilization has an environmental impact somewhere, but it's at least cause to proceed cautiously. In the world in which we now live, anyone investing in this technology won't have a choice about that, anyway.

So it seems we should add salinity power to the existing long list of renewable energy options, including wind, solar, geothermal, ocean thermal, wave and tidal power. If historical precedents concerning the interval from laboratory to commercial application are any guide, we might expect the first large-scale salinity power plant to appear sometime in the mid-to-late 2020s, assuming that it doesn't encounter unexpected hurdles and can be scaled up economically. Even if it can't supply all our needs, salinity power could make an important contribution to the low-emission energy mix we anticipate by mid-century. I'll be watching developments with great interest.

Monday, May 23, 2011

Several trends appear to be converging to make 2011 a watershed year for solar power, though not quite along the lines that solar advocates have been telling us to expect. The long-awaited arrival of "grid parity", when the unsubsidized cost of power from solar panels finally becomes competitive with that of power from the grid, is still either imminent or elusively out of reach, depending on who you ask. In the meantime, solar power remains critically dependent on government incentives. Changes in subsidy levels in key countries and the rapid growth of solar manufacturing in Asia are setting the stage for a shift in the geographical focus of the industry, with important implications for national energy policies.

Last year most of the new solar photovoltaic (PV) capacity in the world was installed in Europe, accounting for roughly 4 out of every 5 Watts of global PV additions. That shouldn't have surprised anyone, because it fits a long-standing pattern. However, the European policies that made it possible for PV to compete, even in such un-sunny northern locations as Germany, have come under considerable pressure as governments have been forced to confront high debt levels and other priorities. Feed-in tariffs (FIT) that guaranteed above-market power prices for the life of a PV installation have been slashed across Europe, including in Germany, Italy and France, in a trend that has lately spread beyond Europe. This is beginning to translate into lower demand. The reason it hadn't already resulted in a big reduction in European PV installations is that the cost of PV was dropping rapidly, further justifying legislated cuts to generous FITs.

Here's where the narrative diverges from the storyline that advocates outside the solar industry have been touting for years. Although a substantial portion of those cost reductions is attributable to economies of scale and experience curve effects--manufacturers finding new ways to cut costs as output climbs--a large slice of the reduction in global PV prices has been due to increased competition from lower-cost producers entering the game. The largest PV manufacturers in the world are now mainly based in China, rather than Europe, and PV producers outside Asia have had to shift much of their manufacturing to lower-cost locations in response. So for the last couple of years we've seen a global PV market focused mainly on sales in Europe but increasingly dominated by export-driven manufacturing in Asia. That picture is now changing as domestic demand in Asia picks up, along with growing installations in the US.

China is rapidly becoming the key country for solar, from both a supply and demand perspective. In addition to hosting leading PV producers such as JA Solar, Suntech Power, Trina Solar and Yngli Green Energy, China's latest five-year plan increases the country's solar power target to 10,000 MW by 2015 and 50,000 MW by 2020. That compares to global solar capacity of around 37,000 MW at the end of 2010, nearly half of which is in Germany. Ramping up installations to meet its new goals, as ambitious as they are, is unlikely to turn China from a net solar exporter to a net importer, as happened earlier for oil. That's because China's PV manufacturers are still adding capacity at a rate that should allow them to satisfy domestic demand in China--where they face only modest competition from foreign firms--while remaining highly competitive elsewhere.

With these developments, policy makers in Europe and the US who have been as focused on the creation of national solar manufacturing industries as on the deployment of solar as an element of their broader renewable energy strategies must answer a crucial question: As the PV industry develops and matures, will it follow the path of wind turbine manufacturing, in which established US and EU firms have been able to remain globally competitive, similar to the aerospace industry, or is it likelier to emulate consumer electronics, for which manufacturing is now dominated by Asian producers? If it's the latter, then the whole system of solar incentives must be rethought.

In the meantime, the shift of the solar power center of gravity away from northern Europe should advance the prospects for grid parity, because low-cost solar power depends as much on high-quality solar resources as on cheap PV panels. Geography isn't always destiny, but in the case of solar power its full potential will only be achieved when its deployment aligns large power demand with high average annual solar irradiance. In the long run, that points to a global PV market focused squarely on the US and China.

Wednesday, May 18, 2011

Roger Cohen's column in Monday's New York Times sent my mind spinning with its portrayal of a global network of airport-based businesses and organizations that might have closer links to airports a country or continent away than with the traditional urban centers for which these facilities are often named. I'm embarrassed to admit that it was the first time I had run across the "Aerotropolis" concept, which has apparently been around since 2000. Its implications are thought-provoking, not least for their impact on energy and the environment.

The term aerotropolis was apparently coined by a professor at the University of North Carolina business school; it's also the title and subject of his new book. It evokes a retro-1920s science fiction vision of gleaming cities connected by flying cylinders, crossed with the gritty reality of the modern airport and its environs. I wasn't surprised to learn that a third of world trade-- though just 1% by weight--moves by air, but the idea of a hospital integrated into an airport in Hyderabad, India, or an entire city in South Korea growing up around the Incheon International Airport was new to me. The possibilities seem endless, though I can't think about them without also considering where the energy to facilitate the implied explosion of air travel and air freight will come from.

A few years ago, I would have said that air travel was even more closely linked to petroleum than are automobiles. That's not because alternative aviation fuels seemed impossible--quite the contrary--but because the aviation world has historically been understandably cautious and conservative about what goes into the engines that power aircraft. From a technical standpoint, jet turbines offer a great deal more fuel flexibility than the internal combustion engines under the hoods of most automobiles. However, while a fuel failure in your car is a major inconvenience, a fuel failure at 30,000 feet is catastrophic. In some respects the alacrity with which the aviation industry has begun to embrace alternative fuels is nearly as big a surprise as the shale gas revolution, and perhaps ultimately as transformative. Airlines and militaries have entered partnerships and set targets for integrating alternative jet fuel into their consumption, and supplies are gradually appearing.

Scale remains an issue. Kerosene-based jet fuel accounted for 7% of US petroleum consumption last year, down from nearly 8.5% a decade ago, as air carriers have transitioned to more efficient aircraft and higher load factors. That's still a big volume, though it turns out to be easier to make suitable kerosene substitutes from a variety of sources, including natural gas, coal and biomass, than to make comparable substitutes for gasoline. Nor does jet fuel produced from camelina seeds, algae, or the gasification and FT-synthesis of bulk biomass, natural gas or even animal fat entail the kind of performance penalties inherent in our primary gasoline alternative, ethanol. Delivering on this potential will require significant investment, but of a magnitude that seems much more achievable than what is required for many other renewable energy goals.

Another important aspect of scale concerns the logistics of gathering enough biomass to produce meaningful quantities of "biojet". The government of Ontario Province just awarded Rentech, Inc., a company with long expertise in gasification and fuel synthesis, a 1.3 million ton-per-year supply of forest waste and other biomass from Canada's Crown Forests, specifically for the production of renewable jet fuel. The proposed facility would produce around 22 million gallons per year of biojet, along with another 11 million gallons of non-jet products. That equates to roughly 1% of Canada's current jet fuel consumption. Canada might have enough forest biomass available to produce a sizable fraction of its jet fuel needs from such sources, but other countries don't, so it's fortunate that alternative jet fuel can be made through so many different pathways.

That's also fortunate for the aerotropolis concept, because without an incremental supply of non-petroleum jet fuel, meeting the energy needs inherent in this idea without dramatic increases in aviation's current approximately 3% share of global greenhouse gas emissions could become a major obstacle within just a few years. With sufficient supplies of renewable and gas-to-liquids jet fuel, the concept might even be able to withstand a peak in global oil output, even if the price of such alternatives seems likely to track that of oil-based jet fuel.

Monday, May 16, 2011

I finally finished watching the archived video from last week's Senate Finance Committee hearing with the heads of the five largest major oil companies in the US, including the two that are based in the EU. The few nuggets of real information and insight that were exchanged were nearly drowned out by political posturing, but my hat is off to Chairman Baucus (D-MT) for his willingness to engage in a genuine give and take with his guests. I attribute much of the frustration that was on display to the conflict between the facts and their context: Although the companies are mostly right on the principles and consequences involved in the proposal to strip them of their tax incentives, it's nearly impossible for anyone outside the industry to get past the large profits these companies are making and the out-of-control federal deficit that the Congress must endeavor to rein in. Perhaps I can offer a bit of perspective for both sides of the argument.

First, neither this Congress nor the administration is proposing windfall profits taxes--government's traditional threat when oil profits soar--nor are there serious calls for nationalization of the industry. Having watched other countries make a hash of such moves, it appears we've learned a thing or two in the last three decades. The measures currently under consideration are much less extreme than that, and I imagine they sounded reasonable and fair to a lot of Americans who are in sticker shock every time they drive by a gas station. However, that doesn't make them good policy--energy or tax.

At the same time, despite Senator Hatch's pie chart showing the relative size of the US oil industry compared to the global industry, including OPEC, few of those grilling the CEOs seemed to grasp the scale involved--a major factor in the absolute magnitude of the profits in question--including the size of companies with which these firms must compete for opportunities around the world. For comparison I couldn't turn up an estimate of Saudi Aramco's first quarter earnings through a Google search, so I had to devise one myself. Based on an average OPEC basket price of $101/bbl and a conservative production cost of $20/bbl, Aramco's average volume of oil exports in January and February, as reported in the database of the Joint Organizations Data Initiative, implies quarterly earnings of around $50 billion--more than the total of the five companies represented at the hearing--and that's assuming that every barrel Aramco refines and sells within the Kingdom is at a breakeven. When it comes to oil profits, big is relative. Even the much smaller Petrobras, 64% owned by the Brazilian government, posted $6.7 B in first quarter earnings, beating US #2 Chevron, in which I own shares.

Several of the Senators complained that the math didn't seem to work, in terms of understanding how the withdrawal of a couple of billion a year in tax incentives could have a serious impact on the five companies and shift investment away from the US, a much more serious concern than the effect on earnings. Having participated in the project portfolio process of a major oil company in the past, I believe I know what the Senators were missing.

It seems counter-intuitive, but corporate-level accounting profits reported after the fact have virtually nothing to do with project selection decisions, other than influencing how much money is available to invest. The choice of which new projects to pursue and which to leave on the shelf hinges on detailed comparisons of expected future after-tax earnings and cash flow for each project. Tax rates, deductions and credits play an important role in those calculations. For some projects the go/no-go decision rests on a knife edge of risked net present value, and in that environment a lost tax deduction (Section 199) or tax credit could make US projects look consistently less attractive than their foreign counterparts. (Ironically, these companies' renewable energy investments in the US would also suffer the same disadvantage.) Put enough US energy projects in that position, and the result is inevitable: fewer wells drilled here, less future US production as current production declines, and eventually a smaller domestic oil industry with fewer capabilities.

Despite a few half-hearted attempts to channel the ghost of William Jennings Bryan, I doubt that any of the Senators participating in the hearing really wants such an outcome. It wouldn't help the millions of Americans who are alarmed by high gas prices, and it's hardly consistent with the President's goals of reducing oil imports by one-third and improving US energy security. Unfortunately, because of the way the question has been framed, in terms of a narrow set of tax breaks the industry enjoys, there are no good answers. Those can only be found by expanding the conversation to encompass a truly constructive US energy policy promoting both conventional and renewable energy, along with meaningful deficit reduction.

Thursday, May 12, 2011

On Monday I was interviewed on Chicago's WGN Radio on the subject of switching the collection of federal highway taxes from the current assessment on motor fuel sales to a fee on vehicle miles traveled (VMT). The gas tax is always a hot-button subject, and when it's combined with potential concerns about privacy it becomes even more controversial. However, the path we're on is a slow-motion train wreck, for multiple reasons, and I'm relieved to see that with so much attention focused on other, larger aspects of the budget deficit and taxation, this relatively small yet important corner of the tax system hasn't been forgotten. It's high time to plan for how we will pay for the upkeep of our highways as sales of gasoline begin to decline.

The interview was prompted by some comments I made on this subject to Tom Curry of MSNBC. Since my conversation with him and then with Mr. McConnell of WGN I've been doing some more thinking about the problem, which I've discussed here since 2005. For some time it's been apparent that we have a disconnect between federal energy policies explicitly aimed at reducing our consumption of petroleum products and a road tax system that depends on the stability and growth of those sales. With gas prices again near their 2008 maximum and the auto industry required to sell consumers a more efficient mix of cars each year, it appears that US gasoline demand might have peaked in July 2007 and won't reach that level again. Lower gasoline sales mean lower gas tax collections, unless the tax rate is steadily increased, encroaching on one of the third-rail issues of US politics.

This is the long-term part of the gas tax problem. It's true that it takes decades to turn over the US passenger car fleet. Nevertheless, the more highly efficient cars are sold, including this year's crop of 40 mpg non-hybrids, plus hybrids, clean diesels, and a tiny but growing number of EVs and other cars using no liquid fuels at all, the harder it will become to fund the cost of road maintenance from its traditional source at the gas pump.

The problem has a more immediate dimension, too, because gas tax collections haven't been sufficient to balance the Federal Highway Trust Fund (HTF) for some time. According to a recent study by the Congressional Budget Office the taxes on gasoline and diesel fuel brought in about $32 billion last year, but between 2008 and 2010 an additional $30 billion had to be transferred from the general fund to the HTF to keep it in the black and avoid canceling or delaying projects. Given the deficit, such transfers add directly to the national debt. Nor is the current level of expenditures adequate to address the decay of many of our roads, as assessed by the American Society of Civil Engineers. This issue received a lot of attention in the aftermath of the 2007 collapse of the I-35W bridge in Minneapolis-St.Paul, but it faded after a few news cycles.

So we need to come up with more money to keep federally-funded highways in good repair, despite the principal funding mechanism being on a gradual but inexorable downward slope. States face a similar dilemma. Solving this problem requires creativity and most likely a new funding mechanism for all or part of a gap that is expected to grow in the years ahead. Simply extending the status quo will require steadily larger transfers from the general fund, exacerbating the deficit. It would also create growing inequities by weakening the long-established link between usage and financial responsibility, compounded by EVs and other vehicles that pay no road taxes at all under the current system. Unless you think EVs will never expand beyond a tiny niche of early adopters, that's unsustainable. (Some might argue that EVs should escape this tax as a further stimulus to sales, but in my view $7,500 per car ought to be inducement enough for anyone interested in buying one.)

There are several possible remedies for shrinking gas tax revenue, with partial or total conversion to a mileage-based system topping the list. It retains the fairness of "user pays" and encompasses all cars, whatever their energy source. It might also trade off a lower tax burden for the drivers of older, less-efficient cars for a slightly steeper bill for newer, more frugal cars. However, considering that the annual federal gas tax bill for someone driving an average car 12,000 miles per year is currently only about $100, any differences between the gas tax and a replacement VMT tax--not to be confused with a VAT tax--would be unlikely to influence car choice one way or the other.

If a VMT tax is the answer, the question of how to assess and collect it looms large. As I noted in the interview I worry about a tendency to rush to a technology solution, even though other options might do the job without requiring GPS-based tracking that a significant number of Americans would consider unacceptably intrusive. If you doubt that, consider the controversy over alleged smartphone tracking by Apple and Google. I would not dismiss low-tech methods such as odometer readings at vehicle inspections, or even self-reported odometer readings where such inspections aren't required. This might introduce new opportunities for fraud, but I'm willing to be that a GPS tracker could be spoofed, and all of these potential loopholes pale compared to the current problem of fuel tax evasion by organized crime and unscrupulous distributors and dealers.

I like the idea of testing this concept in a few locations, particularly if the tests include a wide variety of approaches. The slow uptake of EVs and the gradual shift of total fleet fuel economy give us enough time to find the best solution, if we start now. But lawmakers should ensure that such tests are finite and designed for quick evaluation, so that the window of opportunity presented by the broader tax reform discussions between now and the next presidential inauguration isn't missed.

Tuesday, May 10, 2011

Yesterday I received a joint press release from a group of renewable energy trade associations. It touted a new report from the UN Intergovernmental Panel on Climate Change (IPCC) on the potential growth of renewable energy by 2050. The report has already garnered an impressive array of headlines, such as "Renewable Energy Can Power the World" and "Renewable Energy Key to Solving Climate Change". The headline from the Financial Times was characteristically more concrete, "World faces $15,000 bn renewable energy bill." Unfortunately, although the final report, rumored to run 1,000 pages, might support all of those conclusions when it is issued at the end of the month, the 25-page "Summary for Policymakers" falls far short of inspiring such confidence. Heaven help those policymakers if the summary is all they actually read.

I'm not even sure if "read" is even the correct verb to apply to this document. Once I got beyond the introductory paragraphs it seemed to degenerate into jargon and bureaucratese that was very hard to parse into plain meaning. The report's genesis as the product of pure consensus is readily apparent. Or as Andy Revkin of the New York Times' Dot Earth blog kindly put it, "it doesn't take readers much beyond what is already well established." That's a shame, because we don't need yet another report telling us that we are swimming in enough renewable energy to power our civilization umpteen times over, if we can merely muster the willpower to reach out and tap it. What we urgently need is a roadmap that describes a path--or preferably several possible paths--through the brambles that separate the energy status quo of 2011 from its ideal low-carbon state of 2050.

For example, we need to understand just how renewables will supplant the petroleum that currently provides around 94% of all transportation energy, at least in the US. That demand might be met by biofuels, although the report points out that the first-generation biofuels that supply nearly 3% of global road transport fuel today, but are still the only kind available on a commercial scale, have serious shortcomings. Closing the gap between 3% and 94% would require a true revolution in next-generation biofuels from sources such as cellulose and algae, yet after reading the Summary for Policymakers we are no wiser about when and how this will occur. I might note that such developments are rarely amenable to precise timetables, as the EPA is learning to its chagrin.

The basic message of the summary appears to be that with enough investment, supported by the right policies, the currently identified renewable energy sources could expand by enough that in the very best case (out of 164 scenarios they considered) they could supply roughly as much energy by mid-century as we currently get from fossil fuels. That corresponds to 77% of total expected energy consumption in 2050 and may be the source of the headlines I saw. Of course the median level of those 164 scenarios is quite a bit lower, and the determination of the share of renewables in total energy relies on a projection implying that total global energy consumption will grow by an average of just 0.25% per year over the next 40 years. That suggests either a massive energy efficiency effort or minimal further economic uplift in the developing world. On a more reasonable track of 1% annual energy growth, the top scenario in the scatter chart on page 19 would meet 58% of total 2050 demand, while the median result would cover just a third of global energy needs. That's still impressive, compared to where we are today, but not quite as headline-grabbing.

I will be keenly interested to see what sort of scenarios the IPCC looked at in putting together the report on which this summary is based. Something tells me that they are likelier to fall into the category of what I would call projections or "cases" than true scenarios, which dig deeply into underlying trends and uncertainties and are not merely the output of a mechanistic model. That's not just a technical quibble, because I'm not aware of a single model-type forecast from 1970 that accurately projected the economic and sociopolitical conditions in which we find ourselves today. The intervening improvements in computing power and econometric sophistication still seem insufficient to conquer the fundamental unpredictability of looking that far into the future. But then the IPCC has a built-in bias to accept the results of such work, since long-term climate models underpin its entire effort. I hope I'm not alone in thinking that the expenditure of up to $15 trillion requires a much more rigorous justification than anything provided in this document. Whether or not Saint-Exupery really said it, a goal without a plan is just a wish.

If it seems that I'm being overly critical of a 1,000 page report that I haven't even seen on the basis of the horse-by-committee summary that I have seen, I plead guilty. But isn't that the same sin that the journalists and industry spokespeople are committing when they use this summary as the basis of glowing claims about the potential of renewables? And then there are the politicians and bureaucrats who will attempt to commit vast sums without ever reading any more than summaries such as this--at best--and without questioning the host of assumptions that went into them. If anything, this Summary for Policymakers reinforces my concern that the UN climate process has become so unwieldy and unresponsive that we must look elsewhere for leadership on this complex challenge. Meanwhile, we deserve a clearer articulation of how renewables can overcome the considerable obstacles that stand between their recent impressive performance and the achievement of the milestones this report suggests lie ahead.

Monday, May 09, 2011

The current tax credit for blending grain ethanol into gasoline, the Volumetric Ethanol Excise Tax Credit (VEETC), has outlived its usefulness. That's not just because I consider it unwise to subsidize any industry to such a generous extent for more than thirty years, but also because the passage of the ambitious federal Renewable Fuels Standard in 2007 made it redundant. Refiners aren't just paid to blend ethanol into gasoline; they're required by law to do so. One of the trade associations for the ethanol industry reached a similar conclusion last year, though presumably for different reasons. Nevertheless, the politics of such a big change looked dire. Now it appears that the unthinkable might be happening with the introduction of two separate bills in the Senate, one of which would scale back the ethanol credit significantly, while the other would eliminate it outright.

The tougher of the two bills comes from a pair of Senators representing states that consume far more ethanol than they produce. In fact, I couldn't find a single ethanol plant in Oklahoma, which Senator Coburn (R) represents. Whether the Feinstein-Coburn bill stands a chance or not, I'm much more interested in the equally bi-partisan measure from two farm state senators, Kent Conrad (D-ND) and Charles Grassley (R-IA). As described in the press, it would reduce the VEETC from $0.45 per gallon this year to $0.20/gal. for 2012 and $0.15/gal. for 2013, after which it would fall to a level indexed to oil prices. At the current price of West Texas Intermediate, it would be zero.

Of course the context for the Conrad-Grassley bill is that without legislative action the current blenders credit is due to expire completely at the end of this year. However, we've been in this position before, more than once, and each time the tax credit was rolled over with a few minor tweaks, such as the cut from $0.51/gal. to $0.45/gal. in 2008. My default assumption has been for a similar rollover this year, but with support from the largest ethanol trade groups in the country, the provisions of the Conrad-Grassley Bill appear to have become the new default. The bill also extends some tax credits for cellulosic biofuel and alternative fuel refueling facilities, including E85, and reduces the ethanol import tariff modestly, starting in 2012.

Although outright termination of the corn ethanol tax credit would be justifiable, it would also be highly disruptive to an industry that we've encouraged for so long, and that has struggled with thin margins even with the tax credit in place. A phase-out seems reasonable and would at least save taxpayers up to $3.3 billion next year and more the following year, depending on how much ethanol is actually sold and how many retailers take advantage of the incentives for installing E85 facilities. There's an argument that this might result in higher prices at the pump, as refiners' blending costs rise, though any such impact is likely to be lost in the noise of normal fuel price volatility.

Winding down this subsidy in an orderly fashion is important, but it's even more important that we learn the lessons it teaches. The cultivation of corn and its conversion to ethyl alcohol are subject to natural limits of scale that are lower than those for wind and solar power or plug-in electric cars, all of which also benefit from generous subsidies. Our pockets simply aren't deep enough to repeat our experience with ethanol subsidies with these other energy alternatives. In an era of fiscal limits, alternative energy tax incentives that are orders of magnitude higher per BTU or kilowatt-hour than those enjoyed by conventional energy sources should only be offered for a limited time, and then phased out on a predictable schedule before they take on the mantle of permanent entitlements.

Thursday, May 05, 2011

I just caught up with last week's bankruptcy filing by Raser Technologies, Inc., a small developer of geothermal power plants. Burdened with excessive debt, Raser is filing for Chapter 11 protection to restructure its liabilities and continue operating under new ownership. In the process the current shareholders will see their much-diminished equity wiped out. This outcome is further evidence of just how challenging it is for small, poorly capitalized companies to exploit what is arguably the best, most reliable renewable energy technology in the world, other than hydropower.

Raser's bankruptcy hardly comes as a surprise. The company has been highly leveraged for a long time, and investors were losing patience with the firm. Last year its stock price fell below the minimum listing requirements of the New York Stock Exchange, and it moved to the over-the-counter market, effectively becoming a "penny stock." In the year prior to delisting, Raser had lost more than 80% of its market capitalization, or about $100 million. With only one operating asset generating cash--a 10 MW plant in Utah built with the help of a $33 million renewable energy grant from the US Treasury--and a number of projects under development consuming cash, Raser was losing the race to bootstrap its way into profitability.

Why is it so hard for start-ups to succeed in this space? It's not an accident that the world's largest geothermal operators are mainly big, well-capitalized firms like Chevron, Calpine, or the Green Power spinoff from Italian utility Enel. (Disclosure: I am a Chevron shareholder.) Geothermal developers face some fundamental challenges that require financial flexibility to manage. First is the capital cost of the assets, compared to other power generation technologies. The last figures I saw suggested that the cost of new geothermal capacity per installed megawatt was up to twice that of a wind farm and 4x that of a natural gas turbine. One reason the cost is so high is that it includes a lot more than the above-ground generating hardware.

Geothermal reservoirs must first be discovered, assessed, and drilled. That's why I've long thought that this technology is a natural for oil and gas companies, since it involves many of the same core skills. Geothermal exploration introduces not just additional cost, compared to wind power development, but also a daunting array of risks, including the possibility that the resource won't turn out to be as large as expected, or that its geology won't permit commercially attractive flow rates of steam and/or hot water. In the worst case, this results in the equivalent of a "dry hole", but even if it merely reduces the amount of power a given well can generate, that has a significant impact on project economics that depend on producing power predictably and reliably for decades. In effect, geothermal has all the up-front risks of oil and gas exploration without the quick payoff of a successful oil or gas well.

Geothermal power provides clean energy production for the power grid on a nearly 24/7 basis, something that neither wind nor solar power can match without energy storage capabilities that remain prohibitively expensive today, in most cases. However, it is both capital-intensive and risky to develop. The handful of publicly traded geothermal companies left after Raser's Chapter 11 filing, including firms such as Ormat Technologies and Magma Energy Corp., are doing yeoman work. However, it's hard to envision geothermal energy achieving its full potential without much greater participation from much larger, better-capitalized firms that could pursue such opportunities on a completely different scale.

Tuesday, May 03, 2011

I was very interested to read that Valero, the largest independent refiner in the US, is designing its new gas stations to offer a much wider variety of energy products, including natural gas, E85 ethanol, and potentially recharging facilities for electric vehicles. This is an announcement I've been expecting for more than ten years, and there are good reasons why other companies are likely to follow. At the same time, the economics of doing this now, when the market for non-petroleum fuels is still comparatively small, look challenging. Some will call this a vanity project, and they won't be entirely wrong, even if it also represents the template for the new retail energy facilities that will be built in the next several decades.

Valero's new station design, at least as described in the articles I've seen, embodies the result of trends that my former company, Texaco Inc., identified in the late 1990s in a scenario called Multiple Choice Energy. That view included a combination of new vehicle technologies such as hybrids, EVs and fuel cells, as well as a vision of the retail network that would meet their needs. As attractive as the idea was to many of the top executives to which our team presented, it was a tough sell, because retail fuel is such a difficult business. Margins are slim, competition high, and major redesigns of existing facilities--for rebranding or any other purpose--very hard to justify financially. Several companies have dabbled with elements of this vision, including my former employer, but I'm not aware of anyone deploying the full suite of options in one location.

I think this development, and the company pushing it, is significant for several reasons. First, Valero has already made a major commitment to non-petroleum fuels through its acquisition of ten ethanol plants, bought during a period when the US ethanol industry was being squeezed by poor margins and scarce credit. Those facilities contributed 18% of Valero's operating income in the first quarter of this year, even though they accounted for less than 4% of total output by volume. Adding E85, a blend of 85% ethanol and 15% gasoline, at the company's new stations merely completes a supply chain in which it is already well-established.

Incorporating these capabilities when a station is built, rather than adding them later, is also crucial. It saves a significant amount of money by avoiding the business disruption involved in retrofitting later. E85 faces other challenges, as I discussed recently, but this kind of planning overcomes one of the major impediments to its wider penetration in the US market, which already has millions of flexible fuel vehicles capable of running on it. And for this reason it's especially notable that this initiative is being taken by Valero, which has been expanding its retail network and investing in new sites. That's in contrast to the major oil companies, some of which have been exiting retail, either gradually or on an area-by-area basis, to free up capital for more profitable opportunities in exploration and production.

Adding natural gas and electricity to the array of fuels sold at retail sites is a natural evolution of this strategy but financially much riskier, given the small number of EVs and NGVs on the road so far. Although the company can take advantage of generous tax credits for installing some of these capabilities, the return is likely to be low for some time. EV recharging also requires a large footprint and extra caution, to ensure that it can be done safely in proximity to combustible fuels. Local agencies and fire marshals have definite ideas about this, as I learned when I was involved in plans for recharging facilities for GM's earlier EV-1 plug-in vehicle in the late '90s.

As with the market penetration of the alternative fuel vehicles they will serve, it will be some time before most retail stations offer quite as much choice as Valero's new multi-fuel facility. It takes time to roll out such changes, and the infrastructure can't get too far ahead of the demand for it without its owners going bankrupt in the process. Nor will every new fuel succeed. Methanol blends looked like the next big thing in the 1980s, but they never took off. Still, it wouldn't take many such facilities in each market to break the "chicken-and-egg" barrier that any non-petroleum transportation energy alternative faces. The success of this initiative depends on the demand for these fuels actually materializing. Launching when the average US gasoline price is just a couple of cents below $4.00 looks like good timing to me.

Monday, May 02, 2011

Another oil industry earnings season bolstered by high oil prices has sparked the customary controversies about price gouging and industry subsidies. Last Thursday I participated in ExxonMobil's press call following the release of that company's first quarter earnings. In addition to the responses to my questions about access to non-US energy resources and the progress of the company's algae venture with Synthetic Genomics, I was intrigued by the answer of Ken Cohen, VP of Public and Government Affairs, to a question concerning Exxon's crude oil sales to other refiners. It resonated with my own experience in commodities trading at Texaco in the 1980s and '90s. Not only do major companies like Exxon, Chevron, Shell and BP control only a small fraction of the world's petroleum reserves and production, but they are often large net buyers of crude oil for their refining operations. Understanding the relationship between industry profits, gas prices and the federal tax deductions and credits designed to promote domestic energy production requires a deeper look into the results.

It's discouraging how much confusion still exists in the media concerning oil prices and gasoline prices, as noted in an excellent posting on the topic by Robert Rapier. Members of the public who are convinced that oil companies are manipulating prices to gouge them can always find some poorly reported news story or garbled explanation to justify their belief. Yet while it's certainly true that oil companies benefit from the higher oil prices that result when global demand for petroleum products is strong and supply is constrained and/or subject to unusual risks--both factors are at work today--their interests are not quite as divorced from those of gasoline consumers as they appear, because they are, to a very large extent, also consumers themselves.

A quick look at ExxonMobil's 1Q11 earnings release shows their net global production of crude oil and natural gas liquids at 2.4 million barrels per day (MBD). Meanwhile the company's refineries processed nearly 5.2 MBD in support of global refined product sales of nearly 6.3 MBD. In other words, Exxon had to buy more crude oil from other suppliers than it produced itself in order to feed its refineries, and then still had to acquire more than a million barrels per day of additional refined products from other refiners to meet its marketing demand. Meanwhile, 81% of its nearly $10.7 billion of first quarter earnings was attributable to oil and gas production, and 85% of that was from production outside the US. By comparison, just 6% of that $10.7 billion came from the domestic refining and marketing activities affected by US gasoline prices.

That's a fairly typical pattern for the majors, which have generally been short of crude oil for their refining systems since the big wave of nationalizations and expropriations in the 1970s. My old company, Texaco, refined about twice as much oil as it produced and sold roughly half-again more products than it refined. That meant that my trading colleagues and I were in the market every day, buying crude oil and refined products from our competitors, in order to keep our refineries and marketing outlets supplied. When supplies were tight, the only way to secure what we needed was to bid more than the next company, and that reinforced the dynamic of rising prices until supplies expanded or demand slackened. I see that as of the first quarter, Texaco's successor Chevron Corp. (of which I am a shareholder) produced about as much oil globally as it refined, though not in the US, where it processed 80% more crude than it produced domestically. Global product sales exceeded refinery throughput by more than a million barrels per day. Royal Dutch Shell's results exhibit an even more pronounced case of net purchases of both crude oil and refined products.

So while higher oil prices are good for some parts of these companies' businesses--the exploration and production divisions that contribute the majority of profitability in most years--other business segments find higher prices a mixed blessing, at best. That's particularly true for the parts of these companies with which US consumers have the most contact.

As for the questions I posed to Mr. Cohen, I was somewhat surprised to hear that ExxonMobil isn't looking for the US government to provide it with any assistance in gaining access to resources around the world. Foreign governments routinely help their national and quasi-national oil companies to negotiate for access. ExxonMobil seems able to compete in this arena without help from the US government but is much more concerned about the latter's restrictions on access here at home, and its efforts to tax non-US income that has already been taxed by host governments overseas. And with regard to ExxonMobil's activities in algae, I was informed that R&D is progressing well in both California and in Baytown, TX, where a large pond has just been completed. Mr. Cohen stressed that it was still early days for algae.

The purpose of drawing my readers' attention to the distinction concerning oil companies' large net oil and product purchases isn't to solicit sympathy for an industry that's obviously having a very profitable run, but to remind you that the oil and gasoline price situation is a lot more complicated than suggested by the sound bites we often hear. The biggest companies make most of their profits producing oil and gas outside the US, while refining and marketing here remains a capital-intensive and relatively low-return sideline that many of them have been quietly exiting for years. Ending the industry's tax breaks outside of the comprehensive tax system reform I believe to be necessary probably wouldn't harm the big oil companies as much as it would accelerate their shift away from operations in the US that contribute less to company profits than they do to US energy security.